This disclosure relates to the field of passive seismic evaluation of subsurface formations. More specifically, the disclosure relates to methods for determining subsurface stress fields from seismic events occurring in the subsurface and application of such methods to determining changes in the stress fields induced by activities such as hydraulic fracturing.
Passive seismic evaluation of subsurface formations is used for, among other purposes, determining the origin time and spatial position of microearthquakes (microseismic events) occurring in the subsurface. Example embodiments of such methods are described in U.S. Pat. No. 7,663,970 issued to Duncan et al. and U.S. Pat. No. 8,960,280 issued to McKenna et al.
In general passive seismic methods as descried in the above cited patents include deploying a plurality of seismic sensors above a volume of the Earth's subsurface to be evaluated, and recording detected seismic signals for a selected length of time. The recorded signals may be processed to determine origin time and spatial position (hypocenter) of each seismic event (typically a fracture) that occurs in the subsurface. Determining hypocenters, e.g., during pumping of an hydraulic fracture treatment may enable determining the movement of the fracturing fluid with respect to time. Fracture plane orientation of fractures induced by the hydraulic fracturing may also be determined.
The in-situ stress parameters, i.e. the magnitude and direction of three principal stresses, are key inputs in the design of hydraulic fracturing treatments in unconventional reservoirs. The present disclosure is related to methods for evaluating the stress magnitudes and directions using passive seismic signals.
It is well understood and widely accepted that when injecting hydraulic fracturing fluid into a horizontal well, an induced hydraulic fracture propagates in the direction of the maximum horizontal stress (SHmax), which is the least resistant path to fracture growth. The alignment in time and space of microseismic events can be used to identify the general trend of fracture propagation and thereby obtain a rough estimate of the SHmax direction. However, the accuracy of this method may depend on whether the formation fractures (i.e. natural fractures) are aligned with the SHmax, which may not always be the case. Neither does such method provide any qualitative information on the magnitude of SHmax.
The minimum fracture treatment pressure is a function of stress magnitudes, and more specifically minimum horizontal stress (Shmin). Higher stresses require more fracturing apparatus pump horsepower. Numerical studies along with microseismic observations indicate that the difference between the magnitudes of horizontal stresses, i.e. stress anisotropy, has a considerable impact on the final fracture stimulation pattern, and should be considered when designing the treatment parameters such as stage length and fracturing fluid composition. While density logs and well tests, such as diagnostic fracture injection tests and mini-frac tests are routinely used to estimate the magnitudes of vertical stress and minimum horizontal stress, respectively, there is no direct means available to measure the magnitude of maximum horizontal stress at the fracture treatment depth. It is thus desirable to develop methods to accurately estimate the direction and magnitude of the field maximum horizontal stress using data collected during drilling and completion of the treatment well.
The creation of hydraulic fractures or reactivation of natural fractures changes the stresses within the treatment area. When the fluid pressure inside the hydraulic fracture exceeds the field stress component acting normal to the fracture plane, the fracture will fail and has the potential to dilate and gain width. The amount of fluid pressure required to drive shear failure and dilation depends on the orientation of the fracture plane and the coefficient of friction along the fracture plane in a given stress field.
An estimation of the induced fracture geometry and the variations in the formation stress field can be obtained by mapping the states of stress of the fractures. There is, however, no direct or indirect method to monitor and measure the stimulation-induced stress changes during or after the treatment. It is thus beneficial to develop new methods to estimate and map the stress changes along the well after completion of the well to determine the amount of fluid injection pressures needed to stimulate the rock volume.